Coal measure gas is an important type of unconventional natural gas, and its formation and accumulation are the result of the coupling configuration of tectonic sedimentation. The Lesser Himalayan orogenic belt in Nepal is a key area for studying the development and enrichment patterns of coal measure gas reservoirs in complex structural areas. In this study, the coal measure gas reservoirs of the Gondwana Group and Surkhet Group in the Tansen area of the Lesser Himalayan orogenic belt in Nepal were taken as the research objects. The types and combination characteristics of coal measure gas reservoirs in Gondwana and foreland basins were analyzed. The development of microscopic pore-fracture system morphology and pore structure characteristics of different coal measure gas reservoirs were analyzed. The evolution process of pore-fracture systems and the formation mechanisms of dominant pore-fracture systems in coal measure gas reservoirs under the action of thrust nappe were discussed. Finally, potential favorable reservoirs, favorable areas, and resource potential of coal measure gas were preliminarily predicted. The results showed that: (1) The combination types of coal measure gas reservoirs in the Lesser Himalayan orogenic belt of Nepal mainly included the “source-reservoir integration” type of coal-shale gas, the “lower source-upper reservoir” type of coal-tight sandstone gas and shale gas-tight sandstone gas, and the “source-reservoir adjacent” type of coal-shale gas-tight sandstone gas. (2) The mesopores and organic matter micropores related to shale minerals were well developed, accounting for 64.6% of total pore volume and 98.1% of total specific surface area. The coal seam mainly developed micropores, and the total specific surface area reached 8.22 m²/g. In tight sandstones, intergranular pores and microfractures were predominant, demonstrating the highest permeability among all types of reservoirs. (3) The shale pore-fracture system had the dual effects of destruction and regeneration. The evolution of pore-fracture system in coal measure gas reservoirs with different lithologies varied under the action of thrust nappe. The coal seam mainly experienced cataclastic deformation, resulting in the development of more micropores, while the tight sandstones were mainly characterized by the formation and propagation of structural fractures. (4) The coal-shale combination of the Bhainskati Formation of the Surkhet Group in the Tansen area was the dominant coal measure gas reservoir type. The Jhadewa mining area in the southeast of Tansen area was a potential favorable area for coal measure gas. It was preliminarily estimated that the coal measure gas resources in this area reached 5.04×10⁸ m³. This study preliminarily identifies the potential favorable reservoirs and favorable areas of coal measure gas in the Lesser Himalayan orogenic belt of Nepal, providing direction for the evaluation and exploration of oil and gas resources in Nepal.

Xinjiang has significant advantages in oil-rich coal resources. The efficient and clean utilization of these resources can ensure the supply of oil and gas resources, promote the effective utilization of deep coal resources, and mitigate environmental issues caused by traditional coal combustion. Currently, Xinjiang has achieved certain breakthroughs in understanding the occurrence characteristics, distribution patterns, and shallow development and utilization of oil-rich coal resources. However, bottlenecks remain in key technologies such as the in-situ conversion of deep oil-rich coal and multi-energy collaborative development. This study analyzed the resource of oil-rich coal in Xinjiang and the current status of its development and utilization industry from the perspectives of the geological resource quantity of oil-rich coal, the resource quantity of coal-based oil and gas, the techniques for surface chemical development and utilization, the techniques for underground in-situ pyrolysis and gasification development, geological utilization and storage of by-product CO₂, integrated development of multiple energy sources, and the construction of national-level demonstration zones. Additionally, it proposed suggestions for industrial development. The results showed that: (1) Oil-rich coal resources in Xinjiang were mainly concentrated in the east, including Sandanghu Basin, Balikun Basin, and Tuha Basin. Using the geological block method, volumetric method, and abundance method, it was preliminarily predicted that the oil-rich coal resource quantity in the Jurassic strata within 1 000 meters in eastern Xinjiang was 556.6×10⁸ t, and the coal tar resource was 65.9×10⁸ t. (2) The technologies of surface gasification and pyrolysis upgrading of oil-rich coal and preparation of coal-based chemicals in Xinjiang were relatively mature, having realized the production of clean coal using oil-rich coal as raw material, the production of coal-based hydrogenated oil using coal tar as raw material, and the production of methanol and ethylene glycol using purified coal gas as raw material. (3) An integrated in-situ pyrolysis and gasification development technology system for oil-rich coal was proposed, including the evaluation technology for geological site selection, in-situ furnace construction technology, in-situ coal seam heating technology, and enhanced extraction technology. (4) A technological pathway for the coordinated development of oil-rich coal chemical industry and new energy through multi-energy complementarity was developed. It mainly included using new energy to produce hydrogen, which serves as a raw material for the pyrolysis and hydrogenation of oil-rich coal to prepare chemical products and oil products, provide thermal energy for the pyrolysis and gasification furnace of oil-rich coal, and supply hydrogen as a raw material for pyrolysis upgrading and coking of oil-rich coal. (5) It is recommended that Xinjiang establishes national-level demonstration zones for the development and utilization of oil-rich coal, including a demonstration zone for the surface pyrolysis and gasification of oil-rich coal for the coal chemical industry, an in-situ pyrolysis and gasification demonstration zone for oil and gas industries based on deep oil-rich coal, a geological utilization demonstration zone for by-product CO₂ from oil-rich coal chemical processes, a demonstration zone for CO₂ storage of semi-coke from in-situ pyrolysis of deep oil-rich coal, and a multi-energy complementary coordinated development demonstration zone for “oil-rich coal and new energy”, promoting the efficient and sustainable development of Xinjiang’s oil-rich coal industry.

Coalbed methane (CBM) is a hazardous gas that leads to gas explosions, coal and gas outbursts, and contributes to atmospheric greenhouse effects in coal mines. At the same time, CBM is a clean and efficient energy source. Developing CBM in coal mining areas offers significant benefits for enhanced safety, energy production, and environmental protection. In China, the estimated CBM resource is 32.86 × 10¹² m³ at depths shallower than 2 000 meters and 40.71 × 10¹² m³ at depths beyond 2 000 meters. Since the “12th Five-Year Plan”, an extraction model of “four-zone coordination” has been developed through practical exploration to ensure both CBM resource development and the safe, efficient operation of coal mines. This model is tailored to mining engineering deployment, mining-induced disturbances, and coal seam geological conditions. It involves coordinated CBM development in planning, preparation, production, and goaf areas, demonstrating significant effectiveness in practice. The key outcomes include: (1) Three technologies have been developed for use in planning areas, namely, surface vertical well fracturing, staged fracturing in coal-seam horizontal well, and staged fracturing and extraction. In the Haishiwan Mine of Yaojie, Gansu, vertical well interlayer temporary plugging and diverting fracturing technology is used in the target coal seam, and the CBM well production reaches 2 607 m³/day. In Sihe mine of the Jincheng Mining Area, Shanxi, bottom-sealed coiled tubing pulling hydraulic jet and annulus sand fracturing technology is used in coal seam 15. The length of the horizontal well is 820.53 m with 8 fracturing sections. The maximum well production is 9 100 m³/day, and the stable gas production is 7 000-8 000 m³/day. U-shaped horizontal well staged fracturing is used in the roof of fragmented and soft coal seam 8 of Luling Mine in the Huaibei Mining Area, Anhui Province. The horizontal well length is 585.96 m with 7 fracturing sections. The maximum well production is 10 760 m³/day, and the total production is 7.5 million m³. (2) Directional long borehole staged fracturing and extraction technology in underground coal mines have been developed in preparation areas. In the Dafosi Mine of Binchang, Shaanxi Province, long borehole staged fracturing is used in coal seam 4. The horizontal well length is 600 m with 8 fracturing sections. The maximum pure gas production is 3 600 m³/day, and the average is 1 000-2 500 m³/day. Pure gas production per 100 meters is 4.9-11.0 times that of unfractured boreholes in the same area. In the Xinjing Mine of the Yangquan Mining Area, Shanxi Province, the roof of fragmented and soft coal seam 3 is sand fractured in stages. The drilling length reaches 609 m with 10 fracturing sections. The maximum pure gas production is 2 811 m³/day, and the pure gas production per 100 meters is 5.6-15.4 times that of unfractured boreholes in the same area. (3) For fragmented and soft coal seams, technologies such as high-pressure sand hydraulic fracturing and pneumatic directional drilling have been developed in production areas. In the Pansan Mining Area, Anhui Province, sand hydraulic fracturing technology is used in coal seam 13-1. The pure gas production per 100 meters of sand-fractured borehole is 2.38 times that of conventional water fracturing. In the No.2 Mine of Yangquan, Shanxi Province, to address the difficulties of drilling in fragmented and soft coal seams and the tendency of borehole collapse upon encountering water, pneumatic directional drilling drainage technology is used in coal seam 8. The drilling depth is 607 m, and the pure gas production is 971.6 m³/day. (4) A ground vertical well and L- shaped horizontal well gas extraction model is developed for goaf areas in coal mines. In the Panyi Mine of the Huainan Mining Area, Anhui Province, due to the depressurization mining of coal seam 11-2, ground vertical wells are used to drain gas from coal seam No.13-1, and gas production reaches 50 000 m³/day. In the Sihe Mine, Jincheng Mining Area, Shanxi Province, the L-shaped horizontal well is used in the roof coal seam 3, and the pure gas production is 30 000 m³/day. Innovative technologies such as large-scale staged fracturing both at the surface and underground and deep CBM development have been proposed to promote technological advancement in coal mining areas and ensure the safe mining and efficient development of CBM resources.

The eastern margin of the Ordos Basin is rich in tight gas resources. However, the reservoirs are characterized by low pressure coefficients, poor physical properties, a high concentration of sensitive minerals such as clay minerals, and complex pore structures. These features result in a high degree of potential reservoir damage, which constrains stable and high gas production. To clarify the sensitivity characteristics of tight gas reservoirs in the study area, the study used tight sandstones from the first member of the Permian Shanxi Formation (Shan-1 member) and the eighth member of the Permian Shihezi Formation (He-8 member) as the research objects. Cast thin-section analysis, scanning electron microscopy (SEM), X-ray diffraction, and core fluid displacement tests were employed to investigate reservoir sensitivity. Based on the results, targeted strategies for reservoir protection were proposed. Experimental results indicated that the reservoir rocks were fine to medium grained lithic sandstones, with an average clay mineral content of 21.59%, primarily consisting of mixed-layer illite-smectite. The main pore types were residual intergranular pores and secondary dissolution pores. Nanopores were well-developed, with poor connectivity between micro- and nanopores. In cores from the He-8 member, the median porosity and permeability were 6.43% and 0.149 × 10^-3 μm², respectively. In cores from the Shan-1 member, the median porosity and permeability were 6.46% and 0.387 × 10^-3 μm², respectively. The pH values of the formation water ranged from 5.47 to 6.83, with an average total salinity of 118 077.21 mg/L. The reservoirs in the study area were low-temperature, low-pressure tight gas reservoirs, exhibiting weak velocity sensitivity, weak to moderately weak water sensitivity, weak to moderately weak salt sensitivity, moderately weak to moderately strong acid sensitivity, weak to moderately strong alkali sensitivity, and moderately strong to strong stress sensitivity. The average critical flow velocity was 0.3 mL/min, the critical salinity was 60 000 mg/L, and the average critical pH value was 7.79. During development, attention should be paid to the low pressure, low temperature, and high nanopore proportion of the reservoirs. Acid sensitivity, alkali sensitivity, and stress sensitivity should be prioritized, and improvements and optimizations should be made in drilling, completion, fracturing, and production practices. The research findings provide significant guidance for the efficient development of low-pressure tight sandstone gas resources.

Injecting CO₂ into deep coal seams to enhance coalbed methane (CBM) extraction has both environmental and economic benefits, indicating broad development prospects. To investigate the structural changes of different types of coal after CO₂ injection, five samples with different maximum vitrinite reflectance (R_{o, max}) were selected to conduct supercritical CO₂ injection experiments under conditions simulating a coal seam burial depth of 1 500 m. The pore and fracture structures of the coal samples before and after injection were characterized using low-temperature N₂ adsorption and mercury intrusion porosimetry. The extent of changes was quantitatively compared using fractal theory. The results of N₂ adsorption experiments showed that the pore volume of the coal samples before and after supercritical CO₂-H₂O reaction initially decreased and then increased with increasing coal rank. An inflection point was formed at coking coal, with the most significant increase in pore volume observed within the micropore range (pore diameter 0~2 nm). The changes in pore volume observed in mercury intrusion porosimetry experiments were relatively complex, with significant increases in the transition pore range (pore diameter>2~50 nm) and fracture range (pore diameter>1 000 nm). This was because the supercritical CO₂-H₂O reaction increased the proportion of non-effective connected pores in the coal, enhancing the local connectivity of the coal samples. Furthermore, the total pore volume of some samples even showed a decreasing trend after reaction, likely due to the blockage of pores and fractures by detached minerals. The fractal analysis results of pore parameters before and after reaction showed that the changes in pore and fracture structure depended on the characteristic coal parameters. The changes in pore volume were more pronounced in low-rank and high-rank coals after the reaction, and the extent of change was more significant in samples with higher mineral content. This study contributes to a deeper understanding of how CO₂ injection changes the pore structure of deep coal seams and can provide a reference for site selection in CO₂ geological storage and enhanced coalbed methane development (CO₂-ECBM) projects.

Shale is at the forefront of oil and gas geological research and a hotspot for exploration; however, research has mainly focused on marine and lacustrine shale systems, while studies on shale within transitional coal-measure strata are relatively limited. The Carboniferous-Permian coal-measure strata in the Bohai Bay Basin are well-developed, characterized by widely distributed, regionally stable, and thick shale layers. These strata represent excellent source rocks and reservoirs, indicating significant potential for oil and gas exploration and development. This study investigated the coal-measure shale of the Carboniferous-Permian Taiyuan and Shanxi Formations in the Huanghua Depression of the Bohai Bay Basin. Using data from core analysis, thin sections, well logging, organic carbon content, Rock-Eval pyrolysis, and vitrinite reflectance (R₀), this study examined the depositional environment types of coal-measure shale, the vertical evolution of the depositional environments, and the organic geochemical properties of the shale from different depositional environments. This research aims to provide a theoretical basis for oil and gas exploration in the Carboniferous-Permian coal-measure strata of the Bohai Bay Basin. The Carboniferous-Permian coal-measure strata in the Huanghua Depression were divided into the Taiyuan Formation and the Shanxi Formation. The Taiyuan Formation was mainly characterized by barrier coastal facies, while the Shanxi Formation was dominated by deltaic facies. The shale of the Taiyuan Formation was primarily deposited in lagoon and tidal flat environments of the barrier coastal system, whereas the shale of the Shanxi Formation was mainly deposited in subaqueous distributary channels and interdistributary bay environments of the deltaic system. The lithological and logging characteristics of shale from different sedimentary facies were identified. Lagoon shale was gray-black, with well-developed horizontal laminations. Under the microscope, felsic material was visible, with fine particle sizes generally at the silt grade. Brownish-red siderite concretions were common, often exhibiting irregular ellipsoidal shapes with their long axes typically aligned parallel to the bedding planes. Lagoon shale exhibited distinct logging responses, characterized by high natural gamma and high resistivity on conventional logs, and bright yellow to bright red backgrounds with faint lamination structures on image logs. Tidal flat shale was mainly deposited in tidal flat environments. It was predominantly gray to black or dark gray. In core samples, well-developed felsic bands with a thickness of approximately 1 mm were visible. These felsic bands were laterally discontinuous and tapered off within the core samples. The particles within the bands were fine-grained, mainly silt-sized. Compared to lagoon shale, the tidal flat shale exhibited significantly lower resistivity. In imaging logs, the color appeared noticeably darker. The low response was attributed to the development of felsic bands within the tidal flat shale. The interbedding of thin sand and mud layers resulted in individual shale layers that were thinner than the vertical resolution of resistivity logging tools, leading to the measured apparent resistivity values being lower than the true formation resistivity. Consequently, the resistivity of tidal flat shale in the study area was significantly lower than that of the lagoon shale. Shale in subaqueous distributary channels was dark gray to gray-black and contained abundant siderite concretions occurring in banded and irregularly massive forms. These concretions mainly consisted of microcrystalline siderite grains, with minor felsic detrital particles, and were commonly associated with carbonaceous debris. Carbon and oxygen isotope analyses indicated that the formation of siderite in the delta front was influenced by organic matter and the water chemistry of the depositional environment. After deposition in the delta front, terrestrial carbonaceous debris decomposed, releasing CO₃^2-, which combined with Fe²⁺ in the pore water to form siderite. The water coverage in the delta front also provided favorable conditions for siderite development. The abundant siderite in the shale reduced the formation conductivity and radioactive element content, resulting in low resistivity, uranium, and thorium readings on logs. Conversely, the high photoelectric absorption cross-section (P_e) of siderite increased the P_e value of the formation. Shale in interdistributary bays exhibited diverse colors, including dark gray, gray, and variegated colors, indicating strong water-level fluctuations during deposition and the presence of both subaqueous and emergent environments. Siderite was less developed in the interdistributary bay shale. Consequently, its resistivity and radioactive element content were significantly higher, and its P_e value was significantly lower than those of the subaqueous distributary channel shale. The depositional evolution of the Taiyuan and Shanxi Formations recorded a transition from the peak of the Late Paleozoic marine transgression to subsequent regression. Consequently, the depositional environments of shale transitioned from barrier coastal to deltaic facies, with shale sequentially developing in lagoon, tidal flat, delta front, and delta plain subfacies from bottom to top. The measured total organic carbon content of the shale varied among depositional environments: lagoon shale (0.11%~19.30%, avg. 3.81%), tidal flat shale (0.70%~17.99%, avg. 4.18%), subaqueous distributary channel shale (0.29%~5.91%, avg. 2.45%), and interdistributary bay shale (0.03%~7.36%, avg. 2.21%). A comparison showed that the tidal flat shale had the highest average total organic carbon abundance, followed by lagoon shale, subaqueous distributary channel shale, and interdistributary bay shale. Overall, the organic matter abundance of shale from barrier coastal facies was higher than that from deltaic facies. The organic matter types of shales from different depositional environments were similar, primarily Type III kerogen with some Type II₂, indicating a mixed input of terrestrial higher plants and aquatic lower organisms, with terrestrial higher plants being the dominant source. The measured R₀ values ranged from 0.60% to 1.12%, indicating that the organic matter was generally in a low-maturity to mature stage. The total organic carbon abundance of tidal flat shale (avg. 4.18%) was slightly higher than that of lagoon shale and significantly higher than that of deltaic shales, making it favorable for shale gas generation. The higher content of felsic particles in tidal flat shale enhanced the development of macropores and micropores, which were beneficial for shale gas storage. Meanwhile, the felsic particles increased the brittle mineral content, thereby enhancing the stimulation potential of the shale. Gas logging data also indicated gas-rich intervals within the shale. Overall, the Taiyuan Formation exhibited stronger gas logging responses than the Shanxi Formation, and tidal flat shale outperformed lagoon shale. These characteristics indicated that the tidal flat shale in the upper Taiyuan Formation was the most promising gas-rich interval. During the Early Permian deposition of the upper Taiyuan Formation, the marine transgression in North China mainly originated from the southeast. Tidal flat deposits were extensively developed across most of the Huanghua Depression, while barrier islands and lagoon deposits were confined to the eastern Chenghai area. Tidal flats were primarily distributed in the western part of the Huanghua Depression, with a northeast-southwest trend. Within this trend, the Cangxian uplift, Dongguang, Wumaying, Kongdian, Beidagang, Qibei, and Qinan buried hills were identified as favorable areas for shale gas exploration.

The Xihu Sag in the East China Sea Shelf Basin is a large Mesozoic-Cenozoic oil and gas-bearing sag with abundant oil and gas resources. However, coal-bearing strata are widely developed in this area. In the Pingbei slope zone, the oil and gas-bearing Pinghu Formation strata develop tide-influenced deltaic deposits, characterized by thin interbedded layers of sandstone, mudstone, and coal. The coal seams are thin and develop along with sand bodies. The lithology is mainly dominated by sandstone-mudstone interlayers interbedded with coal, featuring thin single layers, multiple layers, and rapid lateral changes. The thin coal layers in the coal seam section show abnormal features in logging curves, including low velocity, low density, high neutron values, and high resistivity. When conventional acoustic logging curves are used for inversion, the accuracy of sand body prediction is reduced. Therefore, eliminating the influence of coal seams and accurately identifying sand bodies has become an urgent issue. Based on an analysis of the logging curve characteristics of coal-bearing sections, a fitting method for acoustic logging curves in coal measure strata was proposed. Using drilling data, logging observations, and core analysis, the strata were divided into coal-bearing sections and non-coal sections. For non-coal sections, a petrophysical model was constructed for logging curve fitting, which was commonly applied in conventional clastic rock analysis. For coal-bearing sections, fitting was carried out using statistical regression techniques based on empirical formula methods. Subsequently, the results for coal-bearing and non-coal sections were matched and combined. The fitted acoustic primary wave velocity curve corrected the abnormal values caused by borehole collapse in coal seams. The correlation coefficient between the original curve and the fitted curve was 0.82. The fitted and corrected velocity curve was then used for inversion to delineate sand bodies. Application in a gasfield showed that the fitted and corrected acoustic primary wave velocity curve based on this method effectively predicted sand bodies in inversion, and the prediction results were consistent with drilling data, proving useful for identifying lithologic structural traps. This study provides an effective method for reservoir prediction in thin coal measure strata. By separately fitting the acoustic logging curves of coal-bearing and non-coal sections, the interference from coal seams is eliminated, and high-precision sand body prediction is achieved.

During coalbed methane (CBM) production, coal fines within the reservoir can migrate, potentially blocking pore throats and resulting in a significant reduction in reservoir permeability. This process adversely affects the final CBM yield. To investigate the influence of coal fines migration on the porosity and permeability of cataclastic coal reservoirs, this study focuses on the processes of fines initiation, migration, and deposition within reservoir channels. The pore size distribution characteristics of cataclastic coal were analyzed using low-field nuclear magnetic resonance and low-temperature liquid nitrogen adsorption experiments. Subsequently, a three-dimensional pore network model was constructed, and a numerical model for coal fines migration and deposition in pore throat channels was developed. By integrating with an existing mechanical model for coal fines initiation and a probabilistic model for particle deposition and throat blockage, the Monte Carlo method was used to simulate the migration and blockage of coal fines within reservoir pores. A numerical simulation program written in Python was developed to simulate coal fines migration within the pore network of the cataclastic coal matrix. The variations in porosity and permeability of the reservoir during coal fines migration, as well as the influence of this migration, were discussed. The analysis revealed the internal mechanisms by which pressure difference and coal fines particle size influenced coal fines output and model permeability. Both factors were significant, and their interactions were complicated. Specifically, the particle size of coal fines directly affected their migration, deposition, and output characteristics under different hydrodynamic conditions. Under low pressure difference and low flow velocity, large coal fines particles were difficult to mobilize and initiate migration. In contrast, under high pressure difference and high flow velocity, these particles became mobile but were more likely to block effective pores, resulting in a sharp decline in permeability. In addition, an increase in pressure difference had dual effects. It promoted coal fines output but also accelerated permeability decline rate. As the displacement pressure difference increased, the deposition location of coal fines shifted toward the outlet end, accompanied by a higher proportion of small throats. When the coal fines particle size was constant and smaller than the throat radius, a displacement pressure threshold was observed. On either side of this threshold, the relationship between the permeability decline rate and the displacement pressure showed distinct trends. During the drainage and depressurization stages of actual CBM production, the output characteristics and particle size distribution of coal fines served as important indicators for evaluating production efficiency and reservoir permeability changes. As drainage intensity gradually increased, the output intensity of coal fines experienced an initial slow growth followed by a rapid decline. Simultaneously, the particle size distribution of the produced coal fines reached its widest range, encompassing sizes from small to large, particularly during the initial drainage stage. When the drainage intensity was low, only small coal fines particles were mobilized and produced by fluid flow. To further investigate this, numerical simulations were conducted to replicate low drainage intensity conditions by setting a low pressure difference. The simulation results indicated that under low flow rates, small coal fines could indeed migrate and be produced, accompanied by a relatively gentle decline in reservoir permeability. These results were consistent with field observations under low drainage intensity, confirming the accuracy and reliability of the numerical simulation in predicting coal fines migration behavior. Furthermore, the numerical simulation results were compared with those from physical simulation experiments on coal fines migration. The model simulation results showed that as drainage continued, large coal fines particles settled preferentially within the pores. The deposition of these large particles formed channel barriers, blocking pore throats and significantly reducing permeability. Simultaneously, the deposition probability of small coal fines also increased rapidly. This made subsequent migration and production of coal fines increasingly difficult, resulting in a rapid decrease in coal fines production over time. In addition, physical simulation experiments of coal fines migration in cataclastic coal reservoirs provided valuable reference data. The experimental results showed that the permeability decrease of coal samples primarily occurred during the early stage of water flooding, and a higher fracture density corresponded to a higher average permeability. Pores and fissures with diameters greater than 1 000 nm served as the main channels for coal fines migration and blockage. The migrating coal fines further reduced permeability by plugging connected pores larger than 10 000 nm. These findings were consistent with the numerical simulation results, further confirming the alignment between permeability evolution and coal fines production during migration in cataclastic coal reservoirs. In simulations, high drainage intensity was simulated by setting a high pressure difference. When large coal fines were introduced, their deposition locations shifted compared with those under low pressure differences. Also, fines output decreased, and deposition became concentrated near the outlet end. When small coal fines were introduced, fines output increased significantly, and the permeability reduction was less severe than that caused by large coal fines. Overall, the model simulation results were consistent with coal fines output observed in actual production under increased drainage intensity. The numerical simulation results indicated that larger coal fines particles led to more concentrated deposition and blockage near the inlet end, with a smaller overall deposition range. Under low pressure difference, coal fines deposition was mainly concentrated near the inlet end. As the pressure difference increased, the deposition locations of coal fines shifted closer to the outlet end, and the deposition range expanded. In visual physical simulations of coal fines migration within fractures, the deposition area gradually decreased from the inlet toward both ends along and perpendicular to the main migration direction. In summary, the numerical simulation results were consistent with the permeability changes and coal fines deposition patterns observed during coal fines migration in physical simulation experiments.

In the Shenfu block located on the eastern margin of the Ordos Basin, the deep coal seam is intimately interlayered with the tight sandstone layer. During the development of deep coalbed methane, a notable phenomenon has been observed whereby tight sandstone gas from the roof migrates into the coal seam. To date, studies on the impact of roof tight sandstone gas migration on deep coalbed methane production remain scarce. Taking the No.8+9 coal seam and its roof and floor in the Shenfu block as the study object, a numerical simulation of vertical well drainage was conducted for deep coalbed methane under different sandstone coverage ratios (i.e., the proportion of roof sandstone covering the coal seam within the well control range). This study investigated the roles of reservoir pressure conduction, gas desorption/diffusion, and dynamic changes in permeability in governing the influence of roof tight sandstone gas migration on the gas production performance of deep coalbed methane wells and explored its underlying mechanism. The results show that during the development of deep coalbed methane, the migration of roof-tight sandstone gas into the coal seam contributes to the gas output of deep coalbed methane wells. With the increase of roof sandstone coverage, the contribution of tight sandstone gas to cumulative gas production correspondingly increases by 11.43%, 23.54%, and 29.35% at sandstone coverage ratios of 40%, 60%, and 80%, respectively, In comparison to cases with a mudstone roof. Outside the control range of hydraulic fracturing, gas and water production from the sandstone layer occurs more rapidly. This enlarges both the magnitude and spatial extent of the pressure drop within the sandstone layer. As a result, pressure relief is indirectly facilitated in the coal seam, enhancing the rates of gas desorption and diffusion. Additionally, it strengthens the shrinkage effect of the coal matrix and promotes the recovery of permeability ratio. The improvement in permeability further augments the reservoir pressure conduction and gas desorption/diffusion, thereby improving the gas production performance of coalbed methane wells.

The current poor performance of machine learning in predicting oil and gas well production is primarily due to conventional methods relying excessively on historical production data features, which results in predictions that largely reconstruct past information and struggle to predict new trends. These methods overlook other important time-series variables, such as the development stage of oil and gas wells, pressure, and water production, which affect production. To address these issues, this study proposed strategies associating pressure and water production with output and established a novel oil and gas well production prediction method based on a temporal attention and dynamic convolutional neural network (TADyC). This method used a temporal convolutional neural network as the base model and introduced multi-head attention and dynamic convolution mechanisms to capture long-term dependencies between different time steps in the input feature sequence and assign different weights to each time step. The dynamic convolution module dynamically generated convolution kernel parameters based on the output of the temporal attention module, thereby adapting to the input features across different production stages. The superiority of the TADyC-based oil and gas well production prediction model was demonstrated through validation using multiple real and complex well cases from the Anyue gas production area. The results showed that the proposed model achieved better prediction performance when tested on four randomly selected wells. Furthermore, visualization analysis of the attention and dynamic convolution weights revealed that the model could dynamically adjust the convolution kernel weights according to different development stages, particularly for the initial, transition, and decline stages of gas wells. By integrating the relationships between pressure, water production, and production at different development stages, the TADyC model can adaptively adjust its structure and parameters, thereby achieving accurate prediction of oil and gas well production.

Dynamic reserve evaluation is a critical step for reservoir internal adjustment and potential development. For gas reservoirs with single-well production, the traditional material balance method is commonly used. In this method, dynamic reserves are calculated using the average formation pressure and cumulative gas production obtained by extrapolating single-well pressure buildup curves. However, in multi-well production scenarios, inter-well interference exists, and pressure buildup after shut-in often exhibits an abnormal trend of rising first and then declining, making it difficult to accurately determine the average formation pressure. As a result, dynamic reserves predicted by the material balance method may have significant errors. To more accurately evaluate dynamic reserves under inter-well interference conditions, an inter-well interference coefficient was introduced. By coupling the pseudo-steady-state productivity equation of a single well within a rectangular boundary of constant volume (with evenly distributed wells) with the material balance equation, a new method for calculating dynamic reserves was developed using only single-well flowing bottom-hole pressure, gas production rate, and cumulative gas production. Relationship curves were plotted between the pseudo-pressure difference per unit gas production of a single well and the total material balance time, where the inverse of the curve slope represented the dynamic reserves. Given an initial estimate of dynamic reserves, iterative calculations were performed using the curves, and the resulting reserve value was obtained until the error between the calculated and estimated values was sufficiently small. Case studies demonstrated that under inter-well interference conditions, the new method only required single-well flowing pressure, production rate, and reservoir cumulative gas production, without the need for shut-in pressure measurements, showing stronger applicability than the traditional material balance method. It improved calculation accuracy by 12.6% and better aligned with actual production conditions. Additionally, the new method yielded consistent dynamic reserve values when applied to any two connected wells, enabling the determination of inter-well connectivity. The research findings hold significant practical value for improving dynamic reserve calculation accuracy and assessing well connectivity under inter-well interference conditions.

The Huainan mining area is located at the forefront of the intersection of the east-west and north-south tectonic zones in China, with extremely complex geological structures. After a series of tectonic evolution, the coal seams have become fragmented and soft, characterized by “four highs and one softness”: high gas content, high formation pressure, high geothermal temperature, high confined water pressure, and soft and low-permeability coal. As the depth of mining in the Huainan mining area increases year by year, the complexity and hazard of gas disasters have significantly increased, leading to a more prominent contradiction between underground gas control engineering and production succession. Coal mine gas control and coal mining are closely related. Pre-extracting gas through surface gas control wells can effectively prevent gas-related accidents and improve the efficiency of coal safety production. Taking coal mining areas planned for 5 to 10 years as units, surface gas control wells were drilled along the coal mining working face following the track and transportation directions, with an offset of 30~40 m, covering all the designed working faces. Using a three-drilling completion method, rotary casing technology, large-scale fracturing with acidic fracturing fluid system, and drainage and production technology combined with and without sucker rod, the project achieved a 100% success rate, the highest sand ratio of 20% during fracturing, and the highest daily gas production of 11 067 m³ per well. Through verification in the underground coal mines, the original gas pressure in the 13-1 coal seam within the ranges of 65 m and 30 m reduced from 6.8 MPa to 2.7 MPa and 2.4 MPa, respectively, and the gas content decreased from 11.8 m³/t to 7.2 m³/t and 5.2 m³/t, respectively. The fracturing and drainage technology of surface gas control wells had significant effects on reducing the gas pressure and gas content of the coal seam. The implementation of surface gas control technology is beneficial to coal mine safety, energy structure optimization, and carbon emission reduction. Establishing a demonstration area for surface gas control offers valuable insights for implementing surface gas control technology in soft and low-permeability coal seams under geological conditions in China.

Low-rank coalbed methane (CBM) resources in China are approximately 10.3 × 10¹² m³, with the Erlian Basin group accounting for one-quarter of the total, indicating significant potential for large-scale industrial development. The coal reservoirs in the Jiergalangtu block of the Erlian Basin are characterized by six “lows” and one “thick”: low coal rank (vitrinite reflectance R_O of 0.35%), low temperature (26.6 ℃), low Young’s modulus (1 500 to 2 000 MPa), low pressure coefficient (1.02 to 1.03), low gas content (1.8 m³/t), ultra-low tensile stress (7 MPa), and an extremely thick coal seam (vertical thickness of 40 to 128 m). In the early exploration and evaluation stage, 22 wells were fractured and put into production. However, none achieved ideal gas production output due to insufficient geological understanding, immature engineering techniques, and mismatched technical designs. Based on an enhanced understanding of the geological conditions, this study identified the key challenges to development. The low gas content necessitated volume fracturing to achieve industrial-scale gas production. The low temperature required breakthroughs in low-temperature gel-breaking technology to prevent reservoir damage. The extremely thick coal seam necessitated careful selection of high-quality main layers for concentrated stimulation. The low pressure coefficient required strategies to reduce mud loss and fracturing fluid filtration. The strong plasticity required measures to mitigate the impact of proppant embedment on fracture conductivity. After clarifying and addressing these challenges, the research established an integrated geological-engineering fracturing strategy for low-rank coal horizontal wells using energy-focused staged volume fracturing technology. The mechanical specific energy model was modified to calculate the coal rock breakage index, thereby enabling the evaluation of coal fracability and identification of geological-engineering “dual sweet spots” for focused stimulation. A combined fracturing technique of low-temperature soluble bridge plug and perforation was upgraded, and the unperforated casing pumping was used to facilitate adequate operational space for high-displacement fracturing. Perforation parameters were optimized as follows: perforation length of 2 m, hole density of 16 holes/m, and a 60° phased spiral perforation. The fracturing scale and intensity were optimized, with a designed fluid volume of 1 500 m³ per stage, sand addition volume of 180 m³ per stage, and a displacement rate of 18 m³/min. A low-temperature, low-concentration, and low-damage guar gum fracturing fluid system was developed, and a combination of sand addition schemes was used with particle sizes of 0.106-0.212 mm, 0.212-0.425 mm, and 0.425-0.850 mm. This integrated technology was successfully applied to well JP1 in the research area. After fracturing, the well achieved a stable gas production rate exceeding 4 000 m³/day, making it the highest-producing single well among low-rank CBM horizontal wells with cased-hole fracturing in China. This successful application effectively promotes the efficient development of low-rank CBM in China.

High-water-production gas wells experience significant wellbore pressure loss. During production, pressure decline can cause the liquid droplets in the wellbore to fall back and accumulate, forming slug flow. This leads to increased wellbore pressure drop, elevated bottomhole flowing pressure, and reduced production differential pressure and gas production, ultimately resulting in water flooding and production stoppage. Conventional processes such as foam drainage and plunger lift fail to meet the long-term stable drainage requirements of high-water-production gas wells. To this end, an adaptive intelligent drainage and production process for high-water-production gas wells was designed and developed. Guided by the gas-liquid two-phase flow pattern diagram, the downhole gas-liquid separator and distributor were used to reasonably distribute the gas and liquid produced in the formation in the wellbore, maintaining the wellbore gas and liquid flow velocity within the range of annular mist flow. This prevented liquid fallback and slug flow formation, thereby ensuring stable annular-mist flow drainage in the wellbore. An anti-freezing and blocking system and a gas-liquid management platform were designed to ensure the efficient operation of the process. Additionally, an intelligent control system was established to monitor the production status of gas wells in real time and dynamically optimize the gas-liquid production ratio. Well Q1 in Dongsheng gasfield was selected as the experimental well for process application evaluation. The results showed that after the implementation of this process, the average daily gas production was 6 456 m³, an increase of 15.9% compared to that before implementation, and the daily liquid production was 2.64 m³. The production uptime rate increased from 95.3% to 100%, and the pressure monitoring indicated no liquid accumulation in the wellbore. After continuous operation for six months, the process effectively replaced the foam drainage process and gas lift auxiliary drainage measures. Compared with the period before the experiment, the amount of foam drainage agent and gas lift frequency were reduced, resulting in a cost saving of 507 200 yuan. These findings demonstrate the effectiveness and economic efficiency of the proposed technology. This study solves the problems of short liquid accumulation cycle and difficulty in maintaining stable production in high-water-production gas wells. It holds significant implications for reservoir production capacity enhancement, intelligent control of gas wells, and long-term efficient drainage and gas production throughout the entire life cycle.

Drilling multi-lateral horizontal wells is an efficient method for coalbed methane (CBM) development, offering high production potential. This study selected the Bijie test area in Guizhou Province as the research object. This region is characterized by abundant CBM resources, substantial geological reserves, a relatively simple structural setting, and the absence of major fault zones, representing typical geological conditions for CBM development. To identify the suitable lateral well types for this area, a CBM numerical simulation model was established using the PETREL software. Two typical multi-lateral well types, fishbone-shaped lateral wells and fan-shaped lateral wells, were analyzed to investigate their production performance. The study specifically examined the influences of key parameters, including lateral angle, lateral length, and lateral spacing, on production capacity. The differences in development effectiveness between the two well types were quantitatively evaluated using numerical simulations. Differences in drilling difficulty, construction cost, and adaptability were also comprehensively compared. The results showed that within a certain range, the production capacity of fishbone-shaped lateral wells increased with increasing lateral length and the extent of drainage area, but the increase rate decreased beyond a threshold. The production capacity also increased with increasing lateral angle, number of laterals, and well inclination angle. For fan-shaped lateral wells, when the angle between main boreholes ranged from 30° to 90°, the daily gas production increased with larger angles. Similarly, the production capacity increased with increasing lateral length, but the growth rate slowed after a certain threshold. The production capacity also increased with increasing lateral angle and number of laterals. Fishbone-shaped lateral wells demonstrated stronger adaptability under complex geological conditions and could effectively reduce drilling difficulty and construction costs, while fan-shaped lateral wells performed better in enhancing single-well production capacity. Therefore, in practical CBM development, geological conditions, economic costs, and technical capabilities should be comprehensively considered to select the appropriate lateral well type for optimal development performance and economic benefit. This study provides a theoretical basis and practical guidance for the efficient development of CBM in the Bijie test area and similar regions.

The research on utilizing offshore jacket platforms in the East China Sea as offshore CO₂ sequestration and injection platforms is a critical component for the implementation of the East China Sea CCS project. Therefore, it is particularly important to perform accurate fatigue analysis and calculation for the existing jacket platforms. The spectral fatigue analysis method, based on the assumption of linearity of both structural system and wave loading mechanism, can effectively capture the randomness of environmental wave conditions when calculating wave loads and the subsequent structural responses on offshore jacket structures. This method is commonly utilized for the design of offshore jacket platforms and is also suitable for the reassessment of existing jacket structures. Although this method is highly suitable to be applied in offshore platform design and fatigue analysis for deepwater scenarios where nonlinearities between wave height and wave force are not very severe, it has still been widely utilized for the design and assessment of shallow water jacket platforms without carefully considering the possible calculation errors due to strong nonlinear factors between wave heights and wave forces. These errors primarily result from difficulties in choosing appropriate wave heights for a series of wave periods required for producing transfer functions between random wave spectra and structural stress response spectra, due to the significant nonlinearity between wave heights and wave forces mentioned above. This study focused on the potential calculation errors in the spectral fatigue analysis method for shallow water platforms. It presented optimized calculation results from research aimed at reducing the errors in the spectral fatigue analysis method and proposed a new technical approach. This approach could produce more accurate transfer functions between sea state spectra and structural stress response spectra by using the joint probability density function of wave height and period, thereby reducing errors in the spectral fatigue analysis of shallow water platforms and enabling rational utilization of individual local sea state data. Therefore, fatigue damage and service life at the tubular joints of offshore jacket structures could be calculated more accurately. The improved spectral fatigue analysis was applied to the design assessment of jacket platforms in the East China Sea. The results of the fatigue analysis were compared and discussed with those obtained by conventional spectral fatigue analysis methods. In addition, the wave probability density function used for computing fatigue damage in the existing design software was only effective for the narrow-band spectra, and it caused additional errors for the broad-band spectra. This study also discussed improvements in the calculation of fatigue damage for the broad-band spectra. This improved spectral fatigue analysis method can be applied to the structural fatigue life analysis and calculation of the offshore CO₂ injection retrofitted jacket platforms.

The Xianxian County geothermal field in the Bohai Bay Basin is highly developed, providing data support for the refined construction of geothermal field models and the evaluation of geothermal resources. Structurally, the Xianxian geothermal field belongs to the Xianxian County Uplift of the Cangxian County Uplift in the Bohai Bay Basin, with the Fucheng Depression to the east and the Raoyang Depression to the west. The main thermal reservoirs developed in the study area are porous sandstone thermal reservoirs and karst limestone thermal reservoirs. Taking the Wumishan Formation limestone thermal reservoir of the Jixian System as the research object, a multi-scale discrete fracture three-dimensional refined geological modeling method was employed to evaluate the geothermal resources of the Xianxian County geothermal field. The geological structure model of the Xianxian County geothermal field was constructed using deterministic and stochastic modeling methods. The model mesh was set with a step size of 25 m × 25 m, and 300 layers were simulated vertically, with a single layer thickness of 1 m and a total mesh number of 2 333.06 × 10⁴. Under the constraints of the secondary interpretation results of well logging, a geological model of lithofacies, physical properties, and temperature fields of the Wumishan Formation was established. The model analysis showed that the distribution trend of thermal reservoir resources in the Xianxian County geothermal field was positively correlated with the structural morphology of the Xianxian County Uplift. The shallower the burial depth, the better the geothermal resource conditions. Comparison with existing well completion parameter data further validated the model, indicating good adaptability. A volumetric method based on the refined thermal reservoir geological model was employed to evaluate the geothermal resources in the region. The results showed that the total thermal reservoir capacity of the Wumishan Formation in the Jixian System of Xianxian County geothermal field was 2.881 × 10¹⁶ kJ, equivalent to 9.841 × 10⁸ t of standard coal, with a total recoverable heat of 0.432 × 10¹⁶ kJ. The hot water volume was 35.75 × 10⁸ m³, and the heat content in the hot water was 0.105 × 10¹⁶ kJ, equivalent to 0.359 × 10⁸ t of standard coal. These findings confirm the huge potential of geothermal resources in the Xianxian County geothermal field, and the proposed model provides technical support and basis for the subsequent development in the Xianxian County geothermal field.

In the process of converting depleted oil and gas reservoirs into gas storage facilities, identifying and sealing complex old wells is a crucial step. For old wells with ferromagnetic casings, magnetic detection technology is typically employed for localization. However, for open-hole old wells without ferromagnetic beacons, underground positioning relies on inaccurate historical well data, often leading to significant errors. Acoustic remote detection technology, which analyzes acoustic reflection characteristics, theoretically enables the precise positioning of open-hole old wells by detecting and identifying anomalous geological bodies near the borehole. This study systematically investigated the feasibility of this technology for detecting open-hole old wells and their underground positioning from three aspects: acoustic field characteristics, reflection imaging features of an open-hole old well, and data processing and localization for acoustic remote detection. First, a staggered-grid finite-difference time-domain (FDTD) scheme with fourth-order spatial and second-order temporal accuracy was employed to solve the elastic wave equation, simulating acoustic wave propagation around the borehole under various geological conditions. Subsequently, based on acoustic reflection characteristics under actual working conditions and combined with numerical simulation results, the reflection imaging features of the open-hole old well were analyzed. Finally, by processing field data, the detection range and accuracy of the acoustic remote detection technology in practical applications were validated. Experimental results indicated that the acoustic remote detection technology was unaffected by external factors and could effectively determine the spatial position of open-hole old wells at depths up to 3 000 m. The detection range was 4 to 16 m, with a positioning error of less than 0.5 m, indicating its suitability for locating abandoned wells under complex geological conditions. This study demonstrates that acoustic remote detection technology not only overcomes the limitations of traditional positioning methods but also significantly improves the positioning accuracy of open-hole old wells, providing key technical support for the conversion of depleted oil and gas reservoirs into natural gas storage facilities. The application of this technology enhances the safety and efficiency of abandoned well sealing and reduces risks associated with positioning errors. Future research will focus on further optimizing the algorithm, expanding the detection range, and improving positioning accuracy to meet broader engineering requirements.

Reservoir-converted gas storage has emerged as a new development approach worldwide in recent years. Many oil-bearing structures in China meet the conditions for conversion into gas storage, offering broad application prospects for improving oil recovery rates, diversifying gas storage types, and meeting regional gas supply demands. Using a full-diameter core from the Banshen 37 fault block in the Dagang Oilfield and based on the injection-production patterns of reservoir-converted gas storage, a multi-cycle displacement alternating experiment was designed to analyze the seepage mechanisms of converted gas storage in sandstone oil reservoirs and establish a single-well productivity prediction model. The experimental results demonstrate that: (1) Gas exhibits both displacement and extraction effects on water and oil, positively contributing to the enhancement of gas storage capacity. (2) In multi-cycle displacement alternating experiments of gas-water and gas-oil displacement (simulating the late-stage development of water-bearing layers or water-driven oil reservoirs and the early-stage development of converted gas storage in oil reservoirs, respectively), the storage capacity expansion follows a power-law relationship with the number of injection-production cycles, ultimately reaching 27.73% and 33.74%, respectively. Moreover, appropriately lowering the minimum operating pressure of the gas storage can enhance storage capacity. (3) In multi-cycle gas-oil-water displacement alternating experiments (simulating the actual development of converted gas storage in oil reservoirs), under oil-water coexistence conditions, higher water saturation weakens the expansion capacity of the gas storage (with initial water saturation of the core in the two experiments at 47.04% and 63.50%, respectively, leading to expansion capacities of 32.51% and 31.85% , respectively); ④ Based on relative permeability curve tests, a rapid prediction method different from numerical simulation was proposed for single-well productivity of converted gas storage in oil reservoirs. Productivity equations and absolute open flow under different injection-production cycles were established. The findings provide essential guidance for early-stage storage capacity analysis and productivity design of converted gas storage in oil reservoirs.

Five typical continental reservoir crude oils in China were selected as research objects. Single-cycle and multi-cycle injection and production experiments were conducted using a simulation platform for oil-gas phase behavior during injection and production in gas storage reservoirs, which was developed based on ultra-high-pressure fluid phase analysis. Oil-gas properties under multi-stage pressures during single-cycle injection and production were investigated for three types of crude oils with different properties. Oil-gas characteristics during multi-cycle injection and production were examined for two types of crude oils with different properties. These revealed the relationship between interphase mass transfer patterns and the number of construction cycles in the oil and gas system of continental reservoir gas storage construction, providing theoretical guidance for determining the number of construction cycles for converting reservoirs of different types into gas storage. The experimental results showed that: (1) During gas injection, mass transfer was primarily driven by dissolution and diffusion, supplemented by evaporation and extraction. This led to a decrease in the density and viscosity of crude oil, a left-upward shift of the phase envelope, and a shift of the critical point towards lower temperatures and higher pressures. (2) During gas production, mass transfer was dominated by evaporation and extraction, supplemented by dissolution and diffusion. This manifested as increases in crude oil density and viscosity and decreases in gas density and viscosity. When the pressure of the oil and gas system reached the lower limit, the density and viscosity of crude oil reached their maximum values, while the density and viscosity of gas reached their minimum. Meanwhile, the phase envelope shifted left and upward, and the critical point moved towards lower temperatures and higher pressures. (3) Within a single cycle, the gas injection process lightened both volatile oil and heavy oil, reducing the content of heavy components. After gas production down to the lower limit pressure, the content of black oil C₇+ components decreased compared to the initial stage, while the content of volatile oil C₇+ components increased compared to the initial state. (4) Over multiple cycles, as the number of injection and production cycles increased, during the gas production process down to the lower limit pressure, the content of heavy components in black oil first decreased and then increased until it stabilized. The extraction capacity of the gas cap for crude oil was basically zero, indicating the completion of the reservoir construction. For volatile oil during the gas production process down to the lower limit pressure, the content of heavy components in volatile oil first increased and then stabilized. The extraction capacity of the gas cap for crude oil was also basically zero, marking the completion of gas storage construction.

The fluid seepage in oil reservoir-type gas storage involves three phases of oil, gas, and water. The storage capacity not only includes the pore space for gas displacement of liquid, but involves dissolution and component mass transfer between oil and gas. To elucidate the relative permeability characteristics of multiphase displacement among oil, gas, and water and the composition of the gas storage space during cyclic injection and production, multiple cycles of gas-water, oil-water, and gas-oil multiphase displacement and relative permeability experiments were conducted, along with long-core physical simulation experiments under multi-cycle injection and production, based on the operational parameters of reservoir-type gas storage. The seepage patterns of two-phase mutual displacement, gas displacing fluid efficiencies, and fluid saturation changes during cyclic injection and production, and the changes in oil and gas phase states were analyzed. Furthermore, the variations in seepage capacity, oil displacement efficiency, and storage space during cyclic injection and production were investigated. The experimental result showed that: (1) during the processes of multi-cycle two-phase mutual displacement, the water phase reduced the seepage capacity of the gas phase and oil phase, which was unfavorable for the construction and expansion of gas storage facilities. The gas-oil mutual displacement process reduced the residual oil saturation and increased the volume of mobile fluid, which was conducive to the construction and expansion of gas storage facilities. (2) The physical simulation of long-core reservoir construction was performed using the approach of “gas displacement to ultimate recovery under formation pressure + cyclic injection and production within upper and lower pressure limits”. The model’s final oil displacement efficiency reached 65.11%, with 20% from water displacement, 37.51% from gas displacement, and 7.6% from cyclic injection and production. The continuous gas displacement stage was the primary recovery enhancement stage, while the cyclic injection-production stage served as the reservoir construction stage. (3) The pore volume displaced by gas in long-core experiments constituted the main part of the storage capacity, accounting for more than 70%, while the pore volume of solution gas in residual oil and residual oil shrinkage accounted for less than 30%. The storage capacity and working gas volume tended to stabilize after the 14th injection-production cycle, primarily influenced by the gas saturation. Therefore, it is recommended that in the construction of reservoir-type gas storage, premature depletion-driven gas production should be avoided. Instead, a “recovery enhancement” strategy should be prioritized before “reservoir construction”. Reservoir pressure during gas-oil displacement should be maintained until the ultimate recovery efficiency is achieved, after which cyclic injection and production can be implemented to construct the reservoir. This can adequately increase oil and water recovery degree, thereby increasing the storage capacity and working gas volume.